SECTION 5.0 REFINING INDUSTRY DAMAGE MECHANISMS 5.1 General ................................................................................................................................ 1 5.1.1 Uniform or Localized Loss in Thickness Phenomena ................................................ 1 5.1.1.1 Amine Corrosion ......................................................................................................... 1 5.1.1.2 Ammonium Bisulfide Corrosion (Alkaline Sour Water) ......................................... 6 5.1.1.3 Ammonium Chloride Corrosion .............................................................................. 10 5.1.1.4 Hydrochloric Acid (HCl) Corrosion ......................................................................... 12 5.1.1.5 High Temp H2/H2S Corrosion ................................................................................... 15 5.1.1.6 Hydrofluoric (HF) Acid Corrosion ........................................................................... 19 5.1.1.7 Naphthenic Acid Corrosion (NAC) .......................................................................... 27 5.1.1.8 Phenol (Carbolic Acid) Corrosion ........................................................................... 31 5.1.1.9 Phosphoric Acid Corrosion ..................................................................................... 32 5.1.1.10 Sour Water Corrosion (Acidic) ............................................................................ 33 5.1.1.11 Sulfuric Acid Corrosion ....................................................................................... 35 5.1.1.12 Aqueous Organic Acid Corrosion ...................................................................... 39 5.1.2 Environment-Assisted Cracking ................................................................................. 43 5.1.2.1 Polythionic Acid Stress Corrosion Cracking (PASCC) ......................................... 43 5.1.2.2 Amine Stress Corrosion Cracking .......................................................................... 49 5.1.2.3 Wet H2S Damage (Blistering/HIC/SOHIC/SSC) ....................................................... 54 5.1.2.4 Hydrogen Stress Cracking - HF .............................................................................. 64 5.1.2.5 Carbonate Stress Corrosion Cracking (ACSCC) ................................................... 66 5.1.3 Other Mechanisms ........................................................................................................ 77 5.1.3.1 High Temperature Hydrogen Attack (HTHA) ......................................................... 77 5.1.3.2 Titanium Hydriding ................................................................................................... 84 5.2 Process Unit PFD’s .......................................................................................................... 89 5.2.1 Crude Unit / Vacuum ..................................................................................................... 91 5.2.2 Delayed Coker ............................................................................................................... 92 5.2.3 Fluid Catalytic Cracking ............................................................................................... 93 5.2.4 FCC Light Ends Recovery ............................................................................................ 94 5.2.5 Catalytic Reforming – CCR .......................................................................................... 95 5.2.6 Catalytic Reforming – Fixed Bed ................................................................................. 96 5.2.7 Hydroprocessing Units – Hydrotreating, Hydrocracking ......................................... 97 5.2.8 Sulfuric Acid Alkylation ................................................................................................ 98 5.2.9 HF Alkylation ................................................................................................................. 99 5.2.10 Amine Treating ............................................................................................................ 100 5.2.11 Sulfur Recovery........................................................................................................... 101 5.2.12 Sour Water Stripper .................................................................................................... 102 5.2.13 Isomerization ............................................................................................................... 103 5.2.14 Hydrogen Reforming .................................................................................................. 104 5.2.15 Visbreaker .................................................................................................................... 105 5.2.16 Caustic Treating .......................................................................................................... 106 This page intentionally left blank. September 2010 API Recommended Practice 571 5-1 ________________________________________________________________________________________________ 5.1 General Damage mechanisms found in the refining environment are discussed in the following sections. Section 5.2 includes process unit PFD’s. These PFD’s show the location in the unit where particular damage mechanisms are most likely to be found. 5.1.1 Uniform or Localized Loss in Thickness Phenomena 5.1.1.1 Amine Corrosion 5.1.1.1.1 Description of Damage a) Amine corrosion refers to the general and/or localized corrosion that occurs principally on carbon steel in amine treating processes. Corrosion is not caused by the amine itself, but results from dissolved acid gases (CO2 and H2S), amine degradation products, Heat Stable Amine Salts (HSAS) and other contaminants. b) Stress corrosion cracking of carbon steel in amine services is discussed in 5.1.2.2. 5.1.1.1.2 Affected Materials Primarily carbon steel. 300 Series SS are highly resistant. 5.1.1.1.3 Critical Factors c) Corrosion depends on design and operating practices, the type of amine, amine concentration, contaminants, temperature and velocity. d) Amine corrosion is very closely tied to the operation of the unit. With a few exceptions, carbon steel is suitable for most components in a properly designed and operated unit. Most problems can be traced to faulty design, poor operating practices or solution contamination. e) Corrosion is also dependent on the type of amine used. In general, alkanolamine systems can be rated in order of aggressiveness from most to least as follows: monoethanolamine (MEA), diglycolamine (DGA), diisopropylamine (DIPA), diethanolamine (DEA), and methyldiamine (MDEA). f) Lean amine solutions are generally not corrosive because they have either low conductivity and or high pH. However, an excessive accumulation of heat stable amine salts (HSAS) above about 2%, depending on the amine, can significantly increase corrosion rates. g) Lean amine solutions contain a small amount of H2S which helps to maintains a stable iron sulfide film. Overstripped lean solutions can be corrosive if there is inadequate H2S present to maintain the protective iron sulfide film. h) Ammonia, H2S and HCN accelerate corrosion in the regenerator overhead condenser and outlet piping as well as reflux piping, valves and pumps. i) Corrosion rates increase with increasing temperature, particularly in rich amine service. Temperatures above about 220oF (104oC) can result in acid gas flashing and severe localized corrosion due to 2- phase flow, if the pressure drop is high enough. j) Process stream velocity will influence the amine corrosion rate and nature of attack. Corrosion is generally uniform however high velocities and turbulence will cause localized thickness losses. For carbon steel, common velocity limits are generally limited to 3 to 6 fps for rich amine and about 20 fps for lean amine. 5.1.1.1.4 Affected Units or Equipment a) Amine units are used in refineries to remove H2S, CO2 and mercaptans from process streams originating in many units including the crude, coker, FCC, hydrogen reforming, hydroprocessing, and tail gas units. b) The regenerator reboiler and the regenerator are areas where the temperature and turbulence of the amine stream are the highest and can cause significant corrosion problems. 5-2 API Recommended Practice 571 September 2010 ________________________________________________________________________________________________ c) The rich amine side of the lean/rich exchangers, hot lean amine piping, hot rich amine piping, the amine solution pumps, and the reclaimers are also areas where corrosion problems occur. 5.1.1.1.5 Appearance or Morphology of Damage a) Carbon steel and low alloy steels suffer general uniform thinning, localized corrosion or localized underdeposit attack (Figure 5-1 to 5-6). b) Thinning will be uniform in nature when the process stream velocity is low while it will be localized for high velocities associated with turbulence. 5.1.1.1.6 Prevention / Mitigation a) Proper operation of the amine system is the most effective way to control corrosion, with particular attention to acid gas loading levels. In addition, to avoid corrosive amine degradation products, the process temperature should not exceed recommended limits. Proper control of the reboiler rate and temperature is necessary in order to maintain a regenerator top temperature. b) Proper attention should be given to avoid the buildup of HSAS to unacceptable levels. c) The system design should